System for drilling parallel wells for SAGD applications

ABSTRACT

A system for ranging between two wellbores. The target wellbore includes a conductive body (e.g., casing) disposed within a portion of the target wellbore. A second wellbore includes an electromagnetic field sensing instrument positioned within the wellbore. A current delivered to the conductive body in the target wellbore results in a magnetic field emanating from the target wellbore. The electromagnetic field sensing instrument is utilized to measure an electromagnetic gradient based on the magnetic field, which electromagnetic gradient can be utilized to determine the range between the wellbores.

PRIORITY

The present application is a Continuation Application of U.S. patentapplication Ser. No. 14/647,748, filed May 27, 2015, which is a U.S.National Stage patent application of International Patent ApplicationNo. PCT/US2013/073681, filed on Dec. 6, 2013, which claims priority toU.S. Provisional Application No. 61/734,711 entitled, “SYSTEM FORDRILLING PARALLEL WELLS FOR SAGD APPLICATIONS,” filed Dec. 7, 2012,naming Arthur F. Kuckes as inventor, the disclosures of which are herebyincorporated by reference in their entirety.

FIELD OF THE DISCLOSURE

The present disclosure generally relates to wellbore drillingoperations, and more particularly, to methods and systems for trackingthe drilling of multiple wellbores relative to one another. Mostparticularly, embodiments of this disclosure relate to methods andsystems for determining the relative location of a target wellbore froma wellbore being drilled utilizing a magnetic gradiometer in thewellbore being drilled, as well as optimized placement of emitterelectrodes and return electrodes to enhance magnetic ranging.

BACKGROUND

As easy-to-access and easy-to-produce hydrocarbon resources aredepleted, there is an increased demand for more advanced recoveryprocedures. One such procedure is steam assisted gravity drainage(SAGD), a procedure that utilizes steam in conjunction with two spacedapart wellbores. Specifically, SAGD addresses the mobility problem ofheavy oil in a formation through the injection of high pressure, hightemperature steam into the formation. This high pressure, hightemperature steam reduces the viscosity of the heavy oil in order toenhance extraction. The injection of steam into the formation occursfrom a first wellbore (injector) that is drilled above and parallel to asecond wellbore (producer). As the viscosity of the heavy oil in theformation around the first wellbore is reduced, the heavy oil drainsinto the lower second wellbore, from which the oil is extracted.Preferably, the two wellbores are drilled at a distance of only a fewmeters from one other. The placement of the injector wellbore needs tobe achieved with very small margin in distance. If the injector wellboreis positioned too close to the producer wellbore, the producing wellborewould be exposed to very high pressure and temperature. If the injectorwellbore is positioned too far from the producer wellbore, theefficiency of the SAGD process is reduced. In order to assist inensuring that the second wellbore is drilled and positioned as desiredrelative to the first wellbore, a survey of the two wellbores in theformation is often conducted. These surveying techniques aretraditionally referred to as “ranging”.

One solution that has been employed in ranging is to use ranging devicesto directly sense and measure the distance between two wells as thelatter wellbore is drilled. Two wellbore-known commercial approachesthat employ equipment in both wells (injector and producer) are basedeither on rotating magnets or magnetic guidance techniques. However,these approaches are undesirable in that they require two separate anddifferent teams to manage the equipment in each wellbore, namely, awireline team at the producer wellbore and a logging while drilling teamat the injector wellbore, which is not cost effective. One prior artapproach utilizes equipment in only a single wellbore (the injectorwellbore) to transmit a current to a target wellbore (the producerwellbore), after which an absolute magnetic field measurement is used tocalculate distance.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 shows a SAGD drilling system according to certain illustrativeembodiments of the present disclosure;

FIG. 2A illustrates a schematic view of a sensor sub, according to anillustrative embodiment of the present disclosure;

FIGS. 2B and 2C illustrate a cross-sectional view of a sensor sub alonglines B and C of FIG. 2A, respectively;

FIG. 2D illustrates a cross-sectional view of a z-axis sensor;

FIG. 3 is a diagrammatic display of relevant electromagnetic fieldquantities and symbol definitions, according to certain illustrativeembodiments of the present disclosure;

FIG. 4 shows a bottom hole tool assembly and apparatus for calibratingthe magnetic gradient tool of the sensor sub, according to certainillustrative embodiments of the present disclosure;

FIG. 5 is a flow chart of a calibration method for a magnetic gradienttool, according to certain illustrative methods of the presentdisclosure; and

FIG. 6 is a block diagram of a computer system for implementing themagnetic gradiometer calibration system, according to certainillustrative embodiments of the present disclosure.

DESCRIPTION OF ILLUSTRATIVE EMBODIMENTS

Illustrative embodiments and related methodologies of the presentdisclosure are described below as they might be employed in a rangingsystem and method for tracking the drilling of multiple wellboresrelative to one another. In the interest of clarity, not all features ofan actual implementation or methodology are described in thisspecification. It will of course be appreciated that in the developmentof any such actual embodiment, numerous implementation-specificdecisions must be made to achieve the developers' specific goals, suchas compliance with system-related and business-related constraints,which will vary from one implementation to another. Moreover, it will beappreciated that such a development effort might be complex andtime-consuming, but would nevertheless be a routine undertaking forthose of ordinary skill in the art having the benefit of thisdisclosure. Further aspects and advantages of the various embodimentsand related methodologies of the disclosure will become apparent fromconsideration of the following description and drawings.

The foregoing disclosure may repeat reference numerals and/or letters inthe various examples. This repetition is for the purpose of simplicityand clarity and does not in itself dictate a relationship between thevarious embodiments and/or configurations discussed. Further, spatiallyrelative terms, such as “beneath,” “below,” “lower,” “above,” “upper,”“uphole,” “downhole,” “upstream,” “downstream,” and the like, may beused herein for ease of description to describe one element or feature'srelationship to another element(s) or feature(s) as illustrated in thefigures. The spatially relative terms are intended to encompassdifferent orientations of the apparatus in use or operation in additionto the orientation depicted in the figures. For example, if theapparatus in the figures is turned over, elements described as being“below” or “beneath” other elements or features would then be oriented“above” the other elements or features. Thus, the exemplary term “below”can encompass both an orientation of above and below. The apparatus maybe otherwise oriented (rotated 90 degrees or at other orientations) andthe spatially relative descriptors used herein may likewise beinterpreted accordingly.

FIG. 1 illustrates a SAGD drilling system 100 according to anillustrative embodiment of the present disclosure. In this embodiment, atarget wellbore 10 is drilled using any suitable drilling technique.Thereafter, target wellbore 10 is cased with casing string 11. Aninjector wellbore 12 is then drilled using BHA 14 which extends fromderrick 15, as understood in the art. BHA 14 may be, for example, alogging-while drilling (“LWD”) assembly, measurement-while drillingassembly (“MWD”) or other desired drilling assembly. As such, BHA 14further includes a drilling motor 18 and drill bit 20. Althoughinjection wellbore 12 is described as being subsequently drilled, inother embodiments target wellbore 10 and injection wellbore 12 may bedrilled simultaneously. Moreover, in yet another alternate embodiment,BHA 14 may be embodied as a wireline application (without a drillingassembly) performing logging operations, as will be understood by thosesame ordinarily skilled persons mentioned herein. In this exemplaryembodiment, the BHA/drilling assembly 14 includes a sensor sub 16 havingone or more electromagnetic sensors and circuitry for data communicationto and from the surface, as will be described in more detail below.

Generally, the method of the present disclosure includes producing a lowfrequency alternating current on casing string 11 of target wellbore 10by a direct connection to an electric current supply (e.g., AC powersupply) to the target wellbore 10 during periodic interruptions in thedrilling of the wellbore being drilled, i.e., the injection wellbore 12.During these interruptions, measurements are taken at multiple selecteddepth intervals with instruments near the drill bit 20 in the injectionwellbore 12, the measurements including the magnitude, the direction andthe radial gradient of the magnetic field produced by the current flowon the target wellbore 10. At the same time, measurements are made ofthe magnitude and the direction of the Earth's field and of thedirection of gravity in the wellbore being drilled, e.g. by an MWD(measurement while drilling) tool along BHA 14 to determine the rollangle and inclination of the drilling wellbore. Including informationderived from standard MWD measurements, the distance and the directionbetween the injection wellbore 12 and target wellbore 10 and theleft/right direction of drilling (if the wells are in an approximatelyvertical plane with each other) can be determined using the apparatusand method disclosed.

More particularly, and in accordance with certain illustrativeembodiments of the present disclosure, an electric current flow isproduced in casing string 11 of the target wellbore 10 by injectingtime-varying current via the use of an electric current supply (e.g.,electrode (not shown)) disposed in the target wellbore 10 or by directconnection, either at the surface or down-hole location in thatwellbore, as shown in FIG. 1. Current returned at the Earth's surface isdone either by use of a connection 22 to a surface electrode 24 or anearby well head. Connection 22 may be, for example, an insulatedwireline coupling electrode 24 (or some other AC current source, forexample) to an electrical connection 26 connected to casing 11. Thecurrent injected into the target wellbore 10 bleeds off exponentiallywith distance away from the injection point. If current is injected atthe well head, it bleeds off exponentially from that point. If currentis injected into wellbore 10 from a down-hole electrode, the currentbleeds off in both directions from that point, and the net currentavailable for electromagnetic field generation can be computed usingwell known principles.

To enhanced current on the target wellbore 10 near the depth ofmeasurement, an insulating section 28 in that wellbore may be includedas shown in FIG. 1, either on one (as shown) or both sides (not shown)of the target area of investigation. Thus, in one preferred embodiment,a non-conductive element, insulator, gap or insulating section of casingmay be disposed in the target wellbore upstream of the current injectionpoint, thus serving as insulating section 28.

The electromagnetic field sensing instrument housed in sensor sub 16 isextremely sensitive to the electromagnetic fields and most importantlyto the radial gradient of the electromagnetic field in the wellborebeing drilled (i.e., injection wellbore 12). For one application ofinterest i.e., the drilling of SAGD wells, the radial gradient acrossthe injection wellbore 12 is intrinsically about 50 times less thanelectromagnetic field itself, i.e., the ratio of the 7 meter desiredrange and the diametrical size of the electromagnetic gradient measuringinstrument. Thus, a distance measurement with 5% precision preferableutilizes electromagnetic sensors along sub 16 which have an intrinsic1/1000 resolution, stability and signal to noise rejection. Suchprecision is desired not only for eventual oil production requirements,but also to enable the driller to drill a dog leg free wellbore, i.e., astraight bore hole as opposed to a spiral or s-shaped wellbore, as isalso required for easy deployment of steel casing in the injectionwellbore 12.

The use of direct current injection into the target wellbore 10 hasseveral advantages over the prior art method of inducing current flow ona target wellbore by way of a remote electrode or electrode pairdisposed in the wellbore being drilled. When current is injecteddirectly into the target wellbore 10, the dominant current flow in thevicinity of the electromagnetic sensors near the drill bit 20 is fromthe current flowing on the target wellbore 10 itself. However, in theprior art, when current is injected into the target wellbore remotelythrough the Earth formation by means of an electrode or electrodes inthe wellbore be drilled, the opposite is true since typically only a fewpercent of the current injected into the Earth transfers to the targetwellbore in the vicinity of the sensors. The dominant current flow inthis case is in the vicinity of the sensors is in the Earth and wellboresurrounding the wellbore being drilled. Because of the axial symmetryaround the wellbore being drilled the electromagnetic field generated bythese Earth currents, in an idealized configuration is zero. However,given that a 1 part in 1000 measurement specification, non-idealformation properties and down hole drilling assembly location in thewellbore can be bad.

FIG. 2A illustrates a schematic view of sensor sub 16, according to anillustrative embodiment of the present disclosure. FIGS. 2B and 2Cillustrate a cross-sectional view of sensor sub 16 along lines B and C,respectively. FIG. 2D illustrates a cross-sectional view of a z-axissensor. Sensor sub 16, also referred to herein as an electromagneticfield sensing instrument or magnetic gradiometer, being disclosed hereinhas desirable properties for making a good measurement of the radialelectromagnetic field gradient. In certain illustrative embodiments,such a system includes at least three electromagnetic field sensors,separated from each other, with axes of sensitivity perpendicular to thelongitudinal axis of the tool. It is preferable for the system toconsist of 8 primary electromagnetic field component sensors 30, e.g.,of 8 fluxgates or 8 induction coils as shown in FIGS. 2B and C with axesof sensitivity perpendicular to the drilling axis and located as farradially as possible from the axis of the drilling tool as the bottomhole drilling assembly diameter will allow. These sensors 30 are located45 degrees with respect to each other around the drilling axis. Such aconfiguration gives an optimized response to the radial electromagneticfield gradient. In addition, a “z” axis electromagnetic field sensor 32is included for the purpose of determining the relative left/rightdrilling direction with respect to the direction of the target wellbore.Incorporation of a “z” axis sensor 32 is also helpful for compensatingfor the effects of axial components of the electromagnetic field whichmay be present. Z axis sensor 32 is perpendicular to sensors 30 andparallel to the primary axis of sensing sub 16.

As previously described, two features of the illustrative embodiments ofthis disclosure are the method and apparatus for generating electriccurrent flow on the target wellbore and the magnetic gradiometerdisposed in the injector wellbore. With respect to generating electriccurrent flow on the target wellbore 10, preferably low frequency,(approximately 1 to 30 Hertz, for example) electric current with between5 and 30 amperes rms is provided by the current source 24 shown ifFIG. 1. The current return wire (not shown) is connected to a distantreturn electrode (not shown) and the live end to the target wellbore 10.In certain embodiments, this may be accomplished by a clamp to the wellhead itself, or to a ground electrode as close as possible to the wellhead.

An alternative embodiment, as shown in FIG. 1, utilizes an insulatedwire 22 and an electrode (at electrical connection 26) going as deeplyas is convenient into the wellbore 10 to establish electrical contactwith the casing of the reference or target wellbore 10. In thisalternative embodiment, as mentioned above, an optional insulatingsection 28 in the casing string 11 may also be included to force morecurrent in to the vicinity of the measurement depth. In yet anotheralternative embodiment, current is injected into the target wellbore 10using a ground stake 25 in the immediate vicinity of the surfacelocation of the target wellbore 10. For example, at a distance of 2 kminto the wellbore, 3% or more of the current injected can be expected.Tests have shown that for wells spaced apart only a short distance, forexample, 7 meters, this is a sufficient amount of current for themagnetic gradiometer apparatus of this disclosure to function.

Although certain embodiments of the disclosure are not limited to aparticular electromagnetic field gradiometer, one preferred embodimentof an electromagnetic field gradiometer (i.e., sensor sub 16) is shownschematically in FIGS. 2A-2D, utilizing two boards 34 having 8 sensors30. It can be shown that use of a single board 34 with 4 symmetricallylocated sensors 30 (as for example, the upstream board of FIG. 2B with 4sensors as shown) equally spaced about a center axis will result inmagnetic gradient field data with “blindspots” every 90°. Thus, in theembodiment illustrated in FIGS. 2A-2D, 9 induction coil or flux gatesensors 20,32, or their equivalent, are carried by sensor sub 16, with 8electromagnetic field sensors 30 and one z-axis sensor 32. Thisillustrative configuration optimizes signal to noise and also rejectsunwanted “spurious” signals, e.g. those associated with tiny electriccurrent flow on the central core of the instrument.

The induction coil sensors and microprocessor in the MWD unit of BHA 14generate output demodulated DC voltages V1 . . . V8 (8 sensors 30) andVZ (sensor 32) which represent the amplitude ac voltages VH1 . . . VHZproduced by electromagnetic field and amplifiers. The sensors 30, or atleast pairs of sensors, are preferably identical. In certainembodiments, each coil is preferably about 0.1 meters long and hasapproximately 100,000 turns of wire. Each coil is preferably connectedto circuitry (not shown) which includes a low noise, high gain, bandpass amplifier. The amplifier voltages are fed individually into adownhole microprocessor for analysis. The first step in the analysis isto use synchronous demodulation to generate DC voltage outputs V1 . . .V8 and VZ for each of the ac voltages, which voltages are proportionalto the amplitude of the electromagnetic field projection on the sensoraxis at each sensor site. The sensors and their amplifiers produce acvoltages VH1 . . . VH8 and VHz shown in FIGS. 2A-2D, the output ofsensor number “x” is equal to:VHx=Gainx*dot(Hlocx,sax)  Eq. 1.

Hlocx is the electromagnetic field vector present at the location xwhere the sensor x is located, sax is a unit vector pointing in thedirection of sensitivity of sensor x and the function dot(y,z) is thevector dot product of the vectors y and z. Gainx is the ratio of thevoltage output of amplifier “x” and the electromagnetic field projectionin the direction sax being measured.

In certain illustrative embodiments, sensors 30 are spaced symmetricallyon a board 34 or boards 34. In the illustrated embodiment, VH1 . . . VH4are mounted symmetrically on a first board 34 with locations 90 degreesapart and axes of sensitivity unit vectors sa1 . . . sa4 each at adistance “ax” from the center of the drilling sub 16 as indicated.Likewise, sensors VH5 . . . VH8 are mounted symmetrically on a secondboard 34 with locations 90 degrees apart. This second board 34 ismounted slightly below the first board 34 such that, for example, thesensors 30 of the second board are at an angle of 45 degrees relative tosensors 30 of the first board. The sensor VHz is mounted below the VH1 .. . VH8 boards. Also shown schematically are the standard MWD sensorsand the associated electronics for the entire system. It should befurther noted that each pair of sensors 30 can be on the same plane asshown, or different planes.

The mechanical construction of this sub as shown in FIG. 2A has threadedconnections 36 for assembly and disassembly and pin 38 a and box 38 bthreads for connecting to the drill string. The central axis connectionwithin the drilling sub 16 is sealed with O-rings 40 and also has anelectrically insulating sleeve 42 to inhibit electric current flow onthe central axis of the sub 16. Small electric currents on the outershell of the sub 16, to a first approximation, produce noelectromagnetic field inside where the sensors 30 are located. Thoughthe illustrative sensor configuration and method of analysis beingdisclosed are not responsive to current flow on the central core 43, ingeneral even a tiny current on the central core 43 of the sub 16 canimpact operation. Therefore, inhibiting such current flow with aninsulating sleeve 42 and “O” ring 40 is advantageous. It will beappreciated that insulating sleeve 42 forms an insulating gap 41 betweencore 43 and sensors 30. In addition, it is important to house the sensorassembly in an axially symmetric housing 44 with uniform wall thickness.A small electric current flow on the outer wall of such housing producesno field on the inside where the sensors 30 are located. The sub alsoincludes a module 45 which contains, in this example, sensors (MWDgravity earth field sensors, e.g.), data communication and integratedelectronics for the entire tool.

FIG. 3 illustrates relevant electromagnetic filed quantities and symboldefinitions, according to certain illustrative embodiments of thepresent disclosure. The current flow produced on the target wellbore 10generates an electromagnetic field in the vicinity of theelectromagnetic sensors 30. To a good approximation, thiselectromagnetic field circulates about the target wellbore 10 inaccordance with the well-known right hand rule. Also, the primary H0uniform field inside the tool is given by 1/(2*pi*R), where I is thecurrent in amperes on the target wellbore opposite the sensors,pi=3.14156, and R is the center to center radial distance from thetarget wellbore 10 to the drilled wellbore 12 (e.g., injection wellbore)at the depth of measurement.

The detailed magnetic field generated is illustrated in FIG. 3. In thevery close vicinity of the axis of the measuring tool (i.e., sensor sub16), the “circular” electromagnetic field is conveniently represented ina “normal mode” field decomposition as the sum of two components. Thefirst is the that of a uniform field H0 is in the direction of the unitvector q, i.e.,H0=(1/(2*pi*R))*q.  Eq. 2

The second component describes the field “correction” due to the factsthat the field lines are curving and that the field is falling off as1/R. At a radial distance “a” from the center of the measuring tool atan angle Ars, i.e., the angle from the unit radial vector from thetarget wellbore 10 to the electromagnetic sensor location, thecorrection component of the field H1 is given by:H1=(1/(2*pi*R)*(a/R)*(−cos(Ars)*q−sin(Ars)*r).  Eq. 3The voltage output V1 of a sensor at this location is given by:VH=Gain*dot(H,sa)  Eq. 4,where dot(H,sa) is the projection of H on the sensitivity axis sa of thesensor. Gain is the ratio the electronic gain of the amplifier combinedwith the coil voltage response and dot(H,sa).

To present the underlying physical principles of an illustrative method,consider the schematized representations of the sensors shown in FIGS.2A-2D and the electromagnetic field representations in FIG. 3. The“Gain” factor indicated in Eq. 4 is taken to be equal to 1 for thisdiscussion. Using the relations for the unit vectors r, u, sa foridealized sensor locations as indicated in FIGS. 2 and 3, andtrigonometric identities, the following relations of various linearcombinations of the synchronously demodulated voltages V1 . . . V8, VZcan be computed to give the following:VHc1=V1−V3+0.707*(V8+V5−V6−V7)=(4*I/(2*pi*R))*cos(Atr)VHs1=V8−V6+0.707*(V4+V1−V2−V3)=(4*I/(2*pi*R))*sin(Atr)VHc2=−V1−V3+V2+V4)=(4*I*a/(2*pi*R{circumflex over ( )}2))*cos(2*Atr)VHs2=V5+V7−V6−V8)=(4*I*a/(2*pi*R{circumflex over ( )}2))*sin(2*Atr)VZ=(I/(2*pi*R))*sin(ACurZ).  Eq. 5Atr=a tan 2(VHs1,VHc1)R=a*sqrt((VHc1{circumflex over ( )}2+VHs1{circumflex over( )}2)/(VHc2{circumflex over ( )}2+VHs2{circumflex over ( )}2))I/(2*pi*R)=(¼)*sqrt(VHc1{circumflex over ( )}2+VHs1{circumflex over( )}2)ACurZ=a sin((2*pi*R/I)*VZ).  Eq. 6

The angle ACurZ is defined in FIG. 4. Here, it is the angle between Hzand H as shown in FIG. 4. It is also a component of the angle betweenthe “drilling” direction and the reference/target wellbore. The aboverelations give a procedure for computing the roll angle Atr between thetool reference mark and r, the angle between Hz and H (the angle ACurZ)and the distance R between the tool and the target wellbore as shown inFIGS. 2A-2D. The direction of the tool reference mark and direction tshown in FIG. 3 in the Earth and the location of the MWD tool itself arereadily found using standard analyses of MWD gravity and Earth magneticfield sensors measurements (which may be acquired using module 45 inFIG. 2A). Using well known principles of vector addition, these MWDdeterminations can be combined with the above determinations of R andthe angles Atr and ACurZ to find the direction and the location in spaceof the electromagnetic field source point on the target wellboredefined.

It is also important to note, that to a good approximation, a small zcomponent to the electromagnetic field or a small uniform “azimuthal”field component circulating the central core does not give acontribution to the 5 voltage combinations VHc1, VHs1, VHs2, and VZdefined by Eq. 5.

Turning to another important aspect of the disclosure, imperfections intool manufacture can affect response voltages V1 . . . V8 VZ. Sinceprecise response voltages V1 . . . V8 VZ are required for the analysisdefined by Eq. 5 and Eq. 6, tool imperfections must be compensated.Conventionally, this has been accomplished by mechanical and electrical“trimming” methods in the tool. In certain illustrative embodiments ofthis disclosure, however, a better computational method is disclosed.Instead of compensating and calibrating each sensor individually, as hasbeen practiced in the prior art, an overall system and method will bedisclosed which relates the measurements of a set of sensor voltagesmeasured in a given deployment of the tool directly to the desiredquantities, i.e., the distance to the target wellbore, the direction tothe target wellbore and the relative “left/right” direction of drillingand the axial direction of the target wellbore. In one embodiment, thiswill be done by using a Tool Matrix (“TlMat”) which characterizes theoverall tool behavior.

To illustrate this illustrative method of the disclosure, applying themethod to a tool with 9 sensors will be carried out. The method of thedisclosure is not limited to a particular number of sensors and isreadily adapted to tools having other numbers of sensors, such as forexample, 4 or 6 sensors. It is also applicable if no z sensor isincluded in the instrument. An important point is that the method isbased only upon properties of the overall behavior of the tool to theelectromagnetic fields in its vicinity. The specifics of itsconstruction, certainly influence the quality of performance, howeverthese specifics of construction do not enter into the method beingdisclosed to determine the parameters of interest from the tool voltageresponse values.

There are several important points to note at the outset. The first isthat a sensor develops a voltage proportional to the projection of theelectromagnetic field at the sensor location upon the axis ofsensitivity of the sensor. This has the consequence that as the tool isrotated around its longitudinal z axis, in a uniform electromagneticfield H, perpendicular to the axis of rotation, the voltage developed isproportional to the field strength H and to cos(Atr-offset). This offsetangle is related to the orientation of the sensor with respect to thetool and its location in the tool. Thus, the voltage V of a sensor tosuch a uniform field perpendicular to the axis of the tool can bewritten as:V=A*H*cos(Atr−offset)=A*H*(cos(offset)*cos(Atr)+sin(offset)*sin(Atr))=B*(H*cos(Atr))+C*(H*sin(Atr))  Eq.7

A, B and C are proportionality constants related to the sensor gain andlocation and orientation in the tool. The important point to note isthat rotation of the tool in a uniform field, perpendicular to the axisof rotation, can always be expressed a linear combination of termsproportional to cos(Atr) and sin(Atr).

Similarly rotating a sensor in the gradient component of the field,which has the characteristic “hyperbolic” field line shape indicated inFIG. 3, leads to a voltage proportional to a linear combination of termsproportional to cos(2*Atr) and sin (2*Atr). To see how this comes about,consider a sensor “i” shown in FIG. 3 being rotated, i.e., angle Atsi isvaried over 360 degrees. When Atsi is equal to an offset angle of about40 degrees, which FIG. 3 indicates for sensor “i” shown, Arsi=0. WhenAtr=40 degrees, the sensitivity axis sai will be anti-parallel the fieldline H1 and will generate a voltage −Vi. Changing Atsi by 45 degrees,i.e., setting Atr=offset+45 degrees, makes sai perpendicular to thefield line and Vi=0. When Atr=offset+90 degrees, the sensor output willbe +V1 volts because sai and the field line both point in the samedirection. Thus, as the rotation of Atr goes through 360 degrees, theoutput voltage will have go through 720 degrees. Thus, the voltage Vdeveloped from this “G”=dH/dR component of the field comes out to be:V=D*(G*cos(2*Atr))+E*(G*sin(2*Atr))  Eq. 8

Here, D and E are proportionality constants related to constructionaldetails of the tool. Similarly, if the sensor sensitivity axis is notperpendicular to the z axis of the tool, and an Hz component of theapplied field is present, the sensor will generate a voltage which isindependent of the rotation angle Atr, i.e.,V=F*Hz=F*H*sin(ACurZ)  Eq. 9.

In a first step of the method following the above, we write the voltageoutput of a sensor V1 in matrix form as:

$\begin{matrix}{{V\; 1} = {{\begin{matrix}{H^{*}{\cos({Atr})}} & {H^{*}{\sin({Atr})}} & {G^{*}{\cos\left( {2^{*}{Atr}} \right)}} & {G^{*}{\sin\left( {2^{*}{Atr}} \right)}} & {Hz}\end{matrix}}*\mspace{619mu}\left\lbrack \begin{matrix}{V\; 1c\; 1} \\{V\; 1s\; 1} \\{V\; 1c\; 2} \\{V\; 1s\; 2} \\{V\; 1{Hz}}\end{matrix} \right\rbrack}} & {{Eq}.\mspace{14mu} 10}\end{matrix}$

In this relationship, the quantities Vlc1, Vls1, Vic2, Vls2, VlHz aretool constants, i.e., effectively the constants B, C, D, E, and Fconsidered above applied to sensor 1. The row vector HcsHz contains thephysical quantities which characterize the electromagnetic fieldquantities (H and G) and the associated tool rotation angles (Atr) andACurZ, i.e., the quantities which ultimately are determined from a setof tool sensor voltage measurements, one of which is V1.

The linear relationship above is readily extended to include all thesensor output voltages V1 . . . V8 VZ by appending columns as:

$\begin{matrix}{\left| {V\; 1\mspace{14mu} V\; 2\ldots\; V\; 8\mspace{14mu}{VZ}} \right| = \left. {HscHz} \middle| {*\left| \underset{\underset{T\; 1{Mat}}{︸}}{\begin{matrix}{V\; 1c\; 1} & {V\; 2c\; 1} & {V\; 3c\; 1} & {V\; 4c\; 1} & {V\; 5c\; 1} & {V\; 6c\; 1} & {V\; 7c\; 1} \\{V\; 8c\; 1} & {{{VZc}\; 1}\;} & \; & \; & \; & \; & \; \\{V\; 1s\; 1} & {V\; 2s\; 1} & {V\; 3s\; 1} & {V\; 4s\; 1} & {V\; 5s\; 1} & {V\; 6s\; 1} & {V\; 7s\; 1} \\{V\; 8s\; 1} & {\;{{VZs}\; 1}} & \; & \; & \; & \; & \; \\{V\; 1c\; 2} & {V\; 2c\; 2} & {V\; 3c\; 2} & {V\; 4c\; 2} & {V\; 5c\; 2} & {V\; 6c\; 2} & {V\; 7c\; 2} \\{V\; 8c\; 2} & \; & \; & \; & \; & \; & \;\end{matrix}} \right|} \right.} & {{Eq}.\mspace{14mu} 11}\end{matrix}$

It is important to note that this formulation does not require the toolconstruction to closely conform to the idealized tool configuration asdiscussed with regard to Eq. 5 and Eq. 6. The requirement is that theTool Matrix (TlMat) describe a set of mathematically independentequations.

If the Tool Matrix (“TlMat”) defined above is known, the row vector ofinterest called “HcsHz” can be recovered. The Tool Matrix (TlMat) aboveis a table of numbers describing the voltage responses of theelectromagnetic field sensor to an imposed uniform field+a gradientfield+an Hz field. The numbers in the first column of TlMat express thevoltage V1 as an algebraically linear sum of the quantities H*cos(Atr),H*sin(Atr), G*cos(2*Atr), G*sin(2*Atr) and Hz as expressed by equation10. The second column of numbers in TlMat are the coefficients for thevoltage of sensor 2, i.e., V2, and so on. The 1×5 row matrix HcsHz, ofthe applied physical quantities can be recovered from a set ofmeasurements |V1 V2 . . . V8 VZ| using a variation of the least squaresmethod. The row vector HcsHz can be found by applying a Recovery Matrix(RecMat) to a row vector of a set of sensor voltage measurement usingthe expression:HcsHz=|V1 V2 . . . V8 VZ|*RecMat  Eq. 12whereRecMat=TlMat′*inv(TlMat*TlMat′)  Eq. 13

The 5 row by 9 column matrix RecMat (“Recovery Matrix”) can be stored onthe MWD processor, and the 5 quantities in HcsHz computed by the MWDprocessor for communication to the Earth's surface using the MWDwellbore data communication system. This illustrative equation notation,as others in this disclosure, follows that of the computer languageMATLAB. Thus “′” stands for matrix transpose, and the function inv(A) isthe matrix inverse of a square matrix A. The technical computinglanguage MATLAB and the computing environment in which it is embeddeduses matrix manipulations for numerical problem solving, as will beunderstood by those ordinarily skilled in the art having the benefit ofthis disclosure.

From the 1×5 row matrix HcsHz, the desired quantities can be recovered:Atr=a tan 2(HcsHz(2),HcsHz(1))H=sqrt(HcsHz(1){circumflex over ( )}2+HcsHz(2){circumflex over ( )}2R=H/(HcsHz(3){circumflex over ( )}2+HcsHz(4){circumflex over ( )}2)Hz=HcsHz(5)ACurZ=a sin(Hz/H)  Eq. 14

These results are readily combined with the tool roll angle, inclinationand azimuth orientation in space determinations using standard MWDmeasurements and methods of analysis, to give the direction in space andthe relative longitudinal orientation of the target wellbore from theinjection wellbore. Instead of sending HcsHz up hole through the MWDcommunication system it may be advantageous to compute some or all ofthe results shown in Eq. 15 downhole and to send the results of Eq. 14to the Earth's surface.

FIG. 4 illustrates a simplified view of a bottom hole assembly and ahorizontal calibrating loop 400 for calibrating the magneticgradiometric tool (i.e., sensor sub 16). FIG. 5 is a flow chart of acalibration method 500 for the magnetic gradient tool. With reference toFIGS. 4 and 5, the Tool Matrix TlMat can be found using the calibrationapparatus (i.e., loop 400) shown in FIG. 4. Thus, in a block A (FIG. 5),a conductive calibration loop is provided. In certain illustrativeembodiments, the calibration loop 400 is a square planar loop of wireapproximately 30 meters long legs, with known corner locations carries acurrent of the same frequency and current magnitude expected duringdrilling operations. At block B, the tool is positioned adjacent to theloop with its center of sensitivity at a known location in the plane ofthe loop. The values of the magnetic field H, the radial gradient G andthe z component of H, i.e., Hz of that field relative to the adjacentcurrent direction and the tool's longitudinal axis at this location arereadily computed using the law of Biot Savart.

This apparatus includes a mechanism for controllably rotating the rollangle of the tool about its longitudinal axis and also for rotating thelongitudinal axis about a perpendicular axis, which lies in the plane ofthe loop and is perpendicular to H0, the electromagnetic field at thecenter of the tool. This apparatus, and particularly the electromagneticfield which is generated in the vicinity of the tool being calibrated,are closely related to that present while drilling. In the SAGDapplication where the drilling wellbore and the target wellbore areabove each other, the plane of the wells is vertical rather thanhorizontal as in the calibration apparatus. The tool matrix TlMat isfound using this calibration apparatus by noting the tool response to anensemble of tool orientations which simulate those expected in drillingoperations. The tool matrix TlMat can be computed from sets ofmeasurements which constitute an ensemble. In block C, an alternatingcurrent is forced to flow in the calibration loop, and in block D,measurements related to the current are recorded. A set of measurements“i”, i.e., V1 i, V2 i, . . . V8 i, VZi results from a known set ofparameters H, G, Atri, and ACurZi. Following the general formulation,the results V1 i, V2 i, . . . V8 i, VZi for a given member of theensemble are given by (note that Hzi=H0*sin(ACuri)):|V1i V2i . . .V8iVZi|=|H*cos(Atri)H*sin(Atri)G*cos(2*Atri)G*sin(2*Atri)H*sin(ACuri)*TlMat  Eq. 15The entire ensemble of calibration measurements can be entered intomatrices shown below, i.e.,

$\begin{matrix}{\left| \underset{\underset{{{{\,^{*}T}\; 1{Mat}},{{represented}\mspace{14mu}{as}\text{:}}}{MeasMat}}{︸}}{\begin{matrix}{V\; 11\mspace{14mu} V\; 21} & {\ldots\; V\; 81} & {{VZ}\; 1} \\{V\; 12\mspace{14mu} V\; 22} & {\ldots\; V\; 82} & {{VZ}\; 2} \\{{\ldots\ldots\ldots}\mspace{20mu}} & \; & \; \\{{\ldots\ldots\ldots}\mspace{20mu}} & \; & \; \\{V\; 1n\mspace{14mu} V\; 2n} & {\ldots\; V\; 8n} & {VZn}\end{matrix}} \right| = {\mspace{70mu}}\underset{\underset{{= {{CalParMat}*T\; 1{Mat}}}\mspace{599mu}}{︸}}{\begin{matrix}{H^{*}{\cos\left( {{Atr}\; 1} \right)}\mspace{14mu} H^{*}{\sin\left( {{Atr}\; 1} \right)}\mspace{14mu} G^{*}{\cos\left( {2^{*}{Atr}\; 1} \right)}\mspace{14mu} G^{*}{\sin\left( {2^{*}{Atr}\; 1} \right)}} \\{{H^{*}{\sin\left( {{ACur}\; 1} \right)}}\mspace{445mu}} \\{H^{*}{\cos\left( {{Atr}\; 2} \right)}\mspace{14mu} H^{*}{\sin\left( {{Atr}\; 2} \right)}\mspace{14mu} G^{*}{\cos\left( {2^{*}{Atr}\; 2} \right)}\mspace{14mu} G^{*}{\sin\left( {2^{*}{Atr}\; 2} \right)}} \\{{H^{*}{\sin\left( {{ACur}\; 2} \right)}}\mspace{445mu}} \\{{\ldots\ldots\ldots}\mspace{520mu}} \\{{\ldots\ldots\ldots}\mspace{520mu}} \\{H^{*}{\cos({Atrn})}\mspace{14mu} H^{*}{\sin({Atrn})}\mspace{14mu} G^{*}{\cos\left( {2^{*}{Atrn}} \right)}\mspace{14mu} G^{*}{\sin\left( {2^{*}{Atrn}} \right)}} \\{{H^{*}{\sin({ACurn})}}\mspace{445mu}}\end{matrix}}} & {{Eq}.\mspace{14mu} 16}\end{matrix}$The Tool Matrix TlMat can be found using a least squares fit from Eq. 16as:TlMat=inv(CalParMat′*CalParMat)*CalParMat′*MeasMat  Eq. 17.

A convenient ensemble choice for the parameters in the CalParMat is tomake 36 measurements of the quantities V1 . . . V8, VZ. The current inthe calibrating loop 400 is held fixed at a value to make theelectromagnetic field at the sensing instruments comparable to orslightly larger than expected during drilling operations. Thus, thevalue of H and G are held fixed. During the first 12 measurements, i.e.,for i=1 . . . 12, ACurZ is held fixed at say −5 degrees and the toolangle Atr is longitudinally varied in 30 degree increments i.e., 0, 30,60 . . . 330 degrees, as illustrated at block E. For the next 12measurements, i.e., i=13 . . . 24 the tool axis angle ACurZ is axiallyrotated and set to 0 degrees and Atr is again varied through the 0, 30 .. . 330 sequence. For the final 12 measurements, i.e, for i=25 . . . 36ACurZ is set to +5 degrees and Atr is again varied through the 0, 30 . .. 330 degree sequence. Thus, by noting the tool responses V1 . . . V8,VZto each of the above longitudinal and axial rotational orientations ofthe tool, the required numbers which constitute the CalibrationParameter Matrix (CalParMat) and the Measurement Matrix (MeasMat) aboveare generated.

Utilizing the results of foregoing procedures, in block G, theparameters of the electromagnetic gradient field instrument aredetermined in an optimal way. This method, using Eq. 14, determines theRecoveryMatrix (RecMat) from TlMat which gives a simple and direct wayto determine the required radial distance parameter R and the roll angleAtr, i.e., the angle between the tool reference direction and the vectorto the target wellbore. The roll angle Atr is readily combined with thestandard MWD measurement of the tool roll, inclination and azimuthangles in space using the principles of vector addition to give thedirection in space to the target wellbore from the injecting wellbore.

FIG. 6 is a block diagram of an exemplary computer system 100 adaptedfor implementing the magnetic gradiometer calibration system asdescribed herein. In one embodiment, the computer system 100 includes atleast one processor 102, a non-transitory, computer-readable storage104, an optional network communication module 105, optional I/O devices106, and an optional display 108, and all interconnected via a systembus 109. To the extent a network communications module 105 is included,the network communication module 105 is operable to communicativelycouple the computer system 100 to other devices over a network. In oneembodiment, the network communication module 105 is a network interfacecard (NIC) and communicates using the Ethernet protocol. In otherembodiments, the network communication module 105 may be another type ofcommunication interface such as a fiber optic interface and maycommunicate using a number of different communication protocols.

It is recognized that the computer system 100 may be connected to one ormore public (e.g. the Internet) and/or private networks (not shown) viathe network communication module 105. Such networks may include, forexample, servers upon which actual or modeled wellbore ranging dataother data needed for the calibration as described herein is stored.Software instructions executable by the processor 102 for implementingthe magnetic gradiometer calibration system 110 in accordance with theembodiments described herein, may be stored in storage 104. It will alsobe recognized that the software instructions comprising the magneticgradiometer calibration system 110 may be loaded into storage 104 from aCD-ROM or other appropriate storage media.

In certain illustrative embodiments, computer system 100 is utilized toimplement at least a portion of the methods described herein. Forexample, computer system 100 is preferably utilized to generatecalibration matrices, perform the least squares fit operations anddetermine the Tool Matrix as described above.

Note again that the present disclosure may be utilized in a variety ofapplications, including SAGD applications. Other illustrativeapplications include, for example, applications for accurately, andreliably positioning a wellbore being drilled, the “relief/intersecting”wellbore (i.e., second wellbore), with respect to a nearby target firstwellbore, usually the blowout wellbore, so that the second wellboreintersects or avoids the target wellbore as desired. The target wellboremust be of a higher conductivity than the surrounding formation, whichmay be realized through the use of an elongated conductive body alongthe target wellbore, such as, for example, casing that is alreadypresent in most wells to preserve wellbore integrity.

The methods and systems of this disclosure are also particularlydesirable for the drilling of relief wells and/or wellbore avoidanceoperations. In a wellbore avoidance application, a wellbore is drilledutilizing the system described herein, which actively searches for otherwells (or other conductive elongated structures), in the drilling path.If such wells or structures are detected, the positioning system altersthe drill path accordingly. These and other applications and/oradaptations will be understood by those ordinarily skilled in the arthaving the benefit of this disclosure.

Thus, a system for determining distance and direction to a targetwellbore from a second wellbore being drilled has been described.Embodiments of the system may generally to include a conductive bodydisposed in at least a portion of the target wellbore; a drill string inthe wellbore being drilled, the drill string having multiple drill pipesections connected end-to-end and carrying a measurement while drillingsystem; an electric current supply disposed to excite a current flow onthe target wellbore by a direct electrical connection to the targetwellbore; and an electromagnetic field sensing instrument in the secondwellbore being drilled, the electromagnetic field sensing instrumentbeing responsive to the electromagnetic field and to radial gradients ofthe electromagnetic field generated by the electrical current in thetarget wellbore.

Likewise, embodiments of well ranging systems have been described.Embodiments of the system may generally include a first wellbore havinga wellhead at the surface of a formation with an elongated wellboreextending from the wellhead, the wellbore characterized by a proximalend adjacent the wellhead and a distal end, wherein the wellboreincludes an elongated conductive body disposed therein; a source ofalternating current at the surface, the source comprising emitter andreturn electrodes; a second wellbore having an elongated wellboreextending from the surface; a pipe string disposed in the secondwellbore; and a magnetic measurement device carried by the pipe string.

Other embodiments of the well ranging system may generally include afirst wellbore having a wellhead at a surface of a formation with anelongated wellbore extending from the wellhead, the wellborecharacterized by a proximal end adjacent the wellhead and a distal end,wherein the wellbore includes an elongated conductive body disposedtherein; a second wellbore having a an elongated wellbore extending fromthe surface; a pipe string disposed in the second wellbore; a source ofalternating current, the source comprising an emitter and a returnelectrode, wherein the emitter and return electrodes are disposed in thesecond wellbore along the pipe string; and a magnetic gradiometercarried by the pipe string, wherein the current source generates anelectric current that is transmitted from the emitter, and wherein themagnetic gradiometer is configured to respond to a magnetic gradientinduced by a current flowing in the conductive body in the firstwellbore.

Additionally, embodiments of a wellbore tool for locating a targetwellbore containing a conductive body from a second wellbore has beendescribed. The wellbore tool may generally include an electric currentsource comprising an emitter and a return electrode; and a magneticgradiometer, wherein the current source generates an electric currentthat is transmitted from the emitter, and wherein the magneticgradiometer responds to a magnetic gradient induced by a current flowingalong the conductive body in the target wellbore. Moreover, any one ofthe following elements, alone or in combination with each other, may becombined with any of the foregoing embodiments:

-   -   The electric current supply comprises a time varying current.    -   The electromagnetic field sensing instrument comprises an array        of electromagnetic sensors, each electromagnetic sensor        positioned within the second wellbore at a location and        responsive to the electromagnetic field at its location.    -   The conductive body is a casing string disposed in the target        wellbore.    -   Electromagnetic sensors are positioned in the second wellbore so        that the electromagnetic field sensing instrument is responsive        to gradients in the radial direction of a time varying magnetic        field.    -   The direct electrical connection comprises a wire extending from        the second wellbore to the target wellbore.    -   The direct electrical connection comprises an electrode at an        earth surface.    -   The time varying current comprises a low frequency alternating        current.    -   The electromagnetic field sensing instrument comprises a first        board and a second board spaced apart from one another along a        primary axis of the sensing instrument, wherein each board        comprises a plurality of sensors spaced apart from one another        symmetrically about a center axis of the board.    -   Each board of an electromagnetic field sensing instrument        comprises four sensors disposed at 90° from one another around        the axis of the board.    -   The electromagnetic field sensing instrument comprises a first        board and a second board spaced apart from one another along a        primary axis of the sensing instrument and an additional sensor        spaced apart from the boards.    -   An additional sensor is perpendicular to the sensors of boards        of the sensing instrument and parallel to the primary axis of        the sensing instrument.    -   A second board of the sensing instrument is rotated so that        sensors of the second board are at an angle of 45° relative to        sensors of a first board.    -   The electromagnetic field sensing instrument is housed in a        sensor sub, the sensor sub has an outer housing of uniform wall        thickness.    -   The electromagnetic field sensing instrument is housed in a        sensor sub and wherein the sensor sub has a central core which        has an electrically insulating gap.

Thus, a method for determining distance and direction to a first targetwellbore from a second wellbore being drilled has been described. Thetarget wellbore extending from the surface of a formation and containinga conductive body disposed therein. Embodiments of the method maygenerally include producing an alternating current flow on the targetwellbore by direct electrical connection of the conductive body to an ACpower supply; and taking multiple measurements of magnetic field data atselected depth intervals utilizing an electromagnetic gradient fieldinstrument disposed in the second wellbore. Likewise, embodiments ofmethod for performing steam assisted gravity drainage to recoverhydrocarbons from a formation have been described. Embodiments of thismethod may generally include producing an alternating current flow on afirst target wellbore by direct connection of a conductive body in thetarget wellbore to an AC power supply; taking multiple measurements ofmagnetic field data at selected depth intervals utilizing anelectromagnetic gradient field instrument disposed in a second wellbore;injecting steam in the second wellbore to cause hydrocarbons in theformation to migrate to the first wellbore; and recovering hydrocarbonsfrom the first wellbore. Moreover, any one of the following, alone or incombination with each other, may be combined with any of the foregoingembodiments:

-   -   A response of the sensing instrument is used to determine the        distance from the borehole being drilled.    -   The electromagnetic field sensing instrument determines a        relative azimuthal direction of the target well to the wellbore        being drilled.    -   The sensing instrument determines a relative angle between the        direction of the wellbore being drilled and the target well.    -   A response of the sensing instrument is used to determine the        distance from the borehole being drilled and the distance is        determined using a matrix of numbers which characterize the        electromagnetic field sensing instrument response to the        electromagnetic field and radial gradient thereof in the        vicinity of the sensing instrument.    -   The measurements comprise magnitude, direction and radial        gradient of the magnetic field produced by the current flow on        the target wellbore.    -   Measuring, in the wellbore being drilled, the magnitude and a        direction of Earth's field and of a direction of gravity.    -   The alternating current is a low frequency.    -   The frequency of the alternating current is between        approximately 1 to 30 Hertz.    -   Initiating drilling of the second wellbore, and, interrupting        drilling while taking measurements.    -   Positioning an electrode in the target wellbore.    -   Connecting an electrode to the target wellbore at the surface.    -   Connecting an electrode to the conductive body at a location        downhole from the surface.    -   Deploying an insulating section in the conductive body uphole        from the location of the direction electrical connection of the        conductive body.    -   Detecting, in the wellbore being drilled, a radial gradient of        the magnetic field.    -   The current is between approximately 5 and 30 amperes rms.    -   Computing the angle between the roll angle of the instrument and        the target wellbore and computing the distance between wellbore        being drilled and the target wellbore.    -   Drilling the second wellbore; measuring electromagnetic field        gradient; and continuing to drill the second wellbore based on        the measured electromagnetic field gradient.

Thus, a method for calibrating an electromagnetic gradient fieldinstrument has been described. The electromagnetic gradient fieldinstrument is characterized by an elongated, longitudinal axis.Embodiments of the method may generally include providing anelectrically conductive calibrating loop with a select shape disposed ina plane; positioning an electromagnetic gradient field instrumentadjacent the calibrating loop so that the longitudinal axis has a firstorientation relative to the calibrating loop and is disposed within theplane of the calibrating loop; inducing an alternating current in thecalibrating loop; using the electromagnetic gradient field instrument tomeasure an electromagnetic field generated by current in the calibrationloop while the instrument is in the first orientation; longitudinallyrotating the electromagnetic gradient field instrument about a point onthe elongated, longitudinal axis within the plane of the loop to asecond orientation; using the electromagnetic gradient field instrumentto measure the electromagnetic field generated by current in thecalibration loop while the instrument is in the second orientation; andrepeating the longitudinally rotating and measuring for a plurality oforientations to generate measurement data. Moreover, any one of thefollowing, alone or in combination with each other, may be combined withany of the foregoing embodiments:

-   -   The calibrating loop is a square, planar loop.    -   A square planar loop comprises legs approximately 30 meters        long.    -   Estimating the frequency and current magnitude expected during        drilling of wellbore; and utilizing the estimated frequency and        current in the step of inducing.    -   Holding the alternating current at a fixed value.    -   The instrument is longitudinally rotated approximately 30°        during each incremental measurement.    -   The instrument is incrementally longitudinally rotated through        360°.    -   Following repeating the longitudinal rotating and measuring, the        method further comprising axially rotating the tool about the        elongated longitudinal axis and repeating the steps of        longitudinally rotating and measuring.    -   Utilizing the measurement data to generate a voltage matrix;        generating a calibration parameter matrix utilizing orientation        and magnetic field vector data; applying a least squares fit to        the resulting matrix to determine a tool matrix.    -   Adjusting one or more parameters of the electromagnetic gradient        field instrument based on the tool matrix.

Moreover, the methods described herein may be embodied within a systemcomprising processing circuitry to implement any of the methods, or a ina computer-program product comprising instructions which, when executedby at least one processor, causes the processor to perform any of themethods described herein.

Although various embodiments and methods have been shown and described,the disclosure is not limited to such embodiments and methodologies andwill be understood to include all modifications and variations as wouldbe apparent to one skilled in the art. Therefore, it should beunderstood that the disclosure is not intended to be limited to theparticular forms disclosed. Rather, the intention is to cover allmodifications, equivalents and alternatives falling within the spiritand scope of the disclosure as defined by the appended claims.

What is claimed is:
 1. A system for determining distance and directionto a target wellbore, the system comprising: a current source disposedat a surface location; a stationary conductive body disposed at a fixeddownhole location in at least a portion of the target wellbore, thestationary conductive body including an insulating section thereindisposed between the surface location and a distal end of the targetwellbore; an electrical conductor electrically coupled to the currentsource at the surface location and electrically coupled to thestationary conductive body at a location between the insulating sectionof the stationary conductive body and the distal end of the targetwellbore; and an electromagnetic field sensing instrument disposedremotely from the target wellbore, the electromagnetic field sensinginstrument being responsive to an electromagnetic field and to radialgradients of the electromagnetic field generated by an electricalcurrent in the target wellbore.
 2. The system of claim 1, furthercomprising a down-hole electrode coupled to the stationary conductivebody at a current injection point disposed between the insulatingsection of the stationary conductive body and the distal end of thetarget wellbore, the down-hole electrode disposed for injecting theelectrical current into the target wellbore.
 3. The system of claim 2,wherein the stationary conductive body is a casing string, and whereinthe down-hole electrode establishes electrical contact with the casingstring at the current injection point.
 4. The system of claim 1, whereinthe electrical conductor is an insulated wire extending through theinsulating section of the stationary conductive body.
 5. The system ofclaim 1, wherein the electromagnetic field sensing instrument isdisposed in a wellbore being drilled remotely from the target wellbore.6. The system of claim 1, further comprising a ground stake electricallycoupled to the current source, the ground stake disposed at the surfacelocation.
 7. A method of determining distance and direction to a targetwellbore, the method comprising: producing an electrical current with acurrent source disposed at a surface location; transmitting theelectrical current into the target wellbore along an insulatedelectrical conductor that is electrically coupled to the current sourceat the surface location and extends into the target wellbore along aconductive uphole portion of a stationary conductive body disposed in atleast a portion of the target wellbore; transmitting the electricalcurrent through the electrical conductor across an insulating section ofthe stationary conductive body coupled downhole of the uphole conductiveportion; injecting the electrical current through a direct electricalconnection established between the electrical conductor and a downholeconductive portion of the stationary conductive body disposed downholeof the insulating section; inhibiting current flow in the conductiveuphole portion of the stationary conductive body uphole of theinsulating section; and taking measurements of magnetic field data of anelectromagnetic field generated by the electrical current injected intothe downhole conductive portion of the stationary conductive body in thetarget wellbore.
 8. The method of claim 7, further comprising connectinga down-hole electrode to the stationary conductive body at a locationdownhole from the insulating section of the stationary conductive body.9. The method of claim 8, further comprising deploying a casing stringinto the target wellbore, the casing string including an insulatingsection of casing therein, and wherein connecting the down-holeelectrode comprises connecting the down-hole electrode to the casingstring downhole of the insulating section of the casing.
 10. The methodof claim 7, further comprising drilling a wellbore remote from thetarget wellbore based on the measurements of the magnetic field data.11. The method of claim 10, further comprising sensing theelectromagnetic field generated by the electrical current injected intothe downhole conductive portion of the stationary conductive body in thetarget wellbore with an electromagnetic field sensing instrumentdisposed in the wellbore remote from the target wellbore.
 12. The methodof claim 11, further comprising measuring a radial gradient of theelectromagnetic field with the electromagnetic field sensing instrument.13. The method of claim 10, wherein drilling the wellbore includesdrilling above and parallel to the target wellbore.
 14. The method ofclaim 9 wherein connecting the down-hole electrode to the casing stringcomprises connecting the down-hole electrode to the casing string in ahorizontal portion of the target wellbore.
 15. A method of determiningdistance and direction to a target wellbore, the method comprising:deploying a stationary conductive body into the target wellbore, thestationary conductive body including an insulating section definedtherein, a downhole conductive portion disposed downhole of theinsulating portion and an uphole conductive portion disposed uphole ofthe insulating portion; establishing a direct electrical connectionbetween an insulated electrical conductor and the downhole conductiveportion of the conductive body; electrically coupling the insulatedelectrical conductor to a current source disposed at a surface location;producing an electrical current with the current source; transmittingthe electrical current into the target wellbore through the insulatedelectrical conductor along the conductive uphole portion of thestationary conductive body, across the insulating section of the of thestationary conductive body and to the direct electrical connectionestablished with the downhole conductive portion of the stationaryconductive body; injecting the electrical current into the downholeconductive portion of the stationary conductive body through the directelectrical connection; inhibiting flow of the electrical current in theconductive uphole portion of the stationary conductive body uphole ofthe insulating section; and taking measurements of magnetic field dataof an electromagnetic field generated by the electrical current injectedinto the downhole conductive portion of the stationary conductive body.16. The method of claim 15, wherein deploying the stationary conductivebody into the target wellbore includes deploying a casing string intothe target wellbore and wherein the insulating section is defined by aninsulating section of casing.
 17. The method of claim 15, furthercomprising drilling a wellbore remote from the target wellbore andsensing the electromagnetic with an electromagnetic field sensinginstrument disposed in the wellbore remote from the target wellbore. 18.The method of claim 17, wherein drilling the wellbore remote from thetarget wellbore includes drilling above and parallel to the targetwellbore based on the measurements of the magnetic field.
 19. The methodof claim 18, further comprising injecting steam into the wellbore remotefrom the target wellbore, and recovering hydrocarbons from the targetwellbore.
 20. The method of claim 17, further comprising measuring aradial gradient of the electromagnetic field with the electromagneticfield sensing instrument.